Use of calibration injections with microseismic monitoring

ABSTRACT

A method of treating a subterranean formation penetrated by a wellbore is carried out by performing a diagnostic operation wherein a fluid is introduced into the wellbore at a pressure sufficient to create at least one microseismic event within the formation. The at least one microseismic event is monitored. At least one property of the formation surrounding the well is determined based on the monitored at least one microseismic event. A well treatment is performed based upon the determined at least one property of the well wherein the well is modified by the well treatment.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 61/166,342, filed Apr. 3, 2009, which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

Embodiments of this invention relate to methods and fluids used in treating a subterranean formation. In particular, embodiments of the invention relate to creating, monitoring, and adjusting a fluid treatment method based on microseismic measurements and models based on the microseismic measurements. Also, in particular, embodiments of the invention relate to methods to calculate revised reservoir formation and fracture parameters that are used in hydraulic fracture treatment design and hydrocarbon production prediction and estimate.

BACKGROUND

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

Microseismic events have been shown to be mainly triggered by shear movement at formation weaknesses such as faults or joints. During a hydraulic fracturing treatment, both the stress and pore pressure in the formation surrounding the created hydraulic fracture are elevated, and can trigger shear movements and microseismic events. By monitoring and analyzing the microseismic events created from a hydraulic fracturing treatment, the fracture dimensions and other properties can be estimated from the microseismic data.

For the conventional hydraulic fracturing practice, calibration fluid injections are often conducted before a main hydraulic fracturing treatment to determine the formation and fracture properties by analyzing the pressure record during the calibration injections. The analysis of the conventional calibration injections is based on a single fracture and the measured pressure response. In formations containing natural fractures, hydraulic fracture treatments often create complex fracture networks.

Microseismic events induced by fluid injection during treatments have been used to derive the hydraulic properties of reservoir rocks and hydraulic fractures. Improved methods to determine the hydraulic and other properties of a formation, fractures, or fracture networks using the microseismic events are needed.

SUMMARY

A method of treating a subterranean formation penetrated by a wellbore is carried out by performing a diagnostic operation wherein a fluid is introduced into the formation through the wellbore at a pressure sufficient to create at least one microseismic event within the formation. The at least one microseismic event is monitored. At least one property of the formation surrounding the well is determined based on the monitored at least one microseismic event. A well treatment, which may be a fracturing treatment, is performed based upon the determined at least one property of the well wherein the well is modified by the well treatment.

The amount of fluid introduced during the diagnostic operation may be from about 50 bbl (7.95 m³) to about 200 bbl (31.8 m³). The fluid may be a non-gelled fluid. In certain embodiments, the fluid is introduced at a pressure below the fracture pressure of the formation. In others, the fluid is introduced at a pressure above the fracture pressure of the formation. The fluid may be introduced in two or more pulses, wherein each pulse has a different pressure or a different flow rate from the prior pulse. The fluid may be introduced for a duration of from about 1 minute to about 30 minutes. In certain embodiments, at least a portion of the fluid may include a solid particulate material.

The monitoring of the at least one microseismic event may be from an offset well. The monitoring of the at least one microseismic event may occur while the fluid is being introduced or after the fluid has been introduced.

The determined property may be diffusivity, permeability, flow velocity and fracture complexity.

In one particular method, a diagnostic operation is performed wherein a fluid is introduced into the wellbore at a pressure below the fracture pressure of the formation and that is sufficient to create at least one microseismic event within the formation. The at least one microseismic event is monitored. At least one property of diffusivity and permeability is determined based on the monitored at least one microseismic event. A well treatment, which may be a fracturing treatment, is performed based upon the determined at least one property of the well wherein the well is modified by the well treatment.

In another method, a diagnostic operation is performed wherein a fluid is introduced into the wellbore at a pressure above the fracture pressure of the formation and that is sufficient to create at least one microseismic event within the formation. The at least one microseismic event is monitored. At least one property of flow velocity and fracture complexity of a created fracture is determined based on the monitored at least one microseismic event. A well treatment, which may be a fracturing treatment, is performed based upon the determined at least one property of the well wherein the well is modified by the well treatment.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying figures, in which:

FIG. 1 is a plan view of a microseismic plot for a well that has undergone a treatment operation wherein a single fracture is created;

FIG. 2 is a schematic representation of a fracture network of a formation surrounding a wellbore;

FIG. 3 is a schematic representation of multiple hydraulic fractures initiating from a wellbore; and

FIG. 4 is a schematic representation of a complex hydraulic fracture system with dendritic features.

DETAILED DESCRIPTION

In the following detailed description, reference is made to the accompanying drawings that show, by way of illustration, specific embodiments in which the invention may be practiced. These embodiments are described in sufficient detail to enable those skilled in the art to practice the invention. It is to be understood that the various embodiments of the invention, although different, are not necessarily mutually exclusive. For example, a particular feature, structure, or characteristic described herein in connection with one embodiment may be implemented within other embodiments without departing from the spirit and scope of the invention. In addition, it is to be understood that the location or arrangement of individual elements within each disclosed embodiment may be modified without departing from the spirit and scope of the invention. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the present invention is defined only by the appended claims, appropriately interpreted, along with the full range of equivalents to which the claims are entitled.

At the outset, it should be noted that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developer's specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. The description and examples are presented solely for the purpose of illustrating the various embodiments of the invention and should not be construed as a limitation to the scope and applicability of the invention.

In the summary of the invention and this description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the invention and this detailed description, it should be understood that an amount range listed or described as being useful, suitable, or the like, is intended that any and every amount within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors have disclosed and enabled the entire range and all points within the range.

Embodiments of the invention include methods for using calibration fluid injections in conjunction with microseismic monitoring to determine the hydraulic properties of formation, fractures or fracture networks. The calibration fluid injections, also referred to herein as diagnostic fluid injections, have small injection volumes and short injection times and may contain solid particles in the injection fluid. The injection pressure is high enough to create a pressure disturbance in the formation to trigger one or more microseismic events, with or without creating hydraulic fractures. When there is no created hydraulic fracture, by measuring the distance and time lapse between the injection and the microseismic events, the pressure transmission velocity can be calculated and the diffusivity or permeability of the formation can be determined and used for the treatment design. When a hydraulic fracture or fracture network is created, the characteristics of microseismic events related to hydraulic fractures can be used to determine the hydraulic fracture properties that can later be used for the main hydraulic fracturing treatment design.

Prior to performing a well treatment, such as a hydraulic fracturing treatment, a calibration or diagnostic operation is carried out. In this operation, a calibration fluid is injected into the well. The calibration injection includes introducing the calibration fluid into the formation through the wellbore at a specified flow rate for a short period of time. This period may vary, but injection periods may range from about 1 minute to about 30 minutes, more typically from about 5 minutes to about 15 or about 20 minutes. In certain embodiments, the total volume of fluid used for the calibration injection may be from about 50 bbl (7.95 m³) to about 200 bbl (31.80 m³). This is contrasted with fluid injections that are used in performing the treatment itself, which typically have much longer injection periods of injection of from 2 to 3 hours or more and much higher volumes {e.g. 1000 bbl (159 m³) or more}. The calibration injection may then be followed by a period of shut-in, where no fluid is injected. The period of shut-in may range from a few minutes to 2 hours or more, and may vary depending upon the permeability of the formation. With lower permeability formations the shut-in period may be longer than for high permeability formations. The monitoring of microseismic events may occur during the injection of the calibration fluid or after the injection of the calibration fluid during a shut-in period, or both.

The fluids used for the calibration injections may be the same or different than those used for the subsequent treatment. In many cases, a non-gelled fluid may be used in the diagnostic operation because the required fluid properties of the treating fluid may be unnecessary for the diagnostic operation. In many cases, water or other aqueous fluid may be used as the calibration injection fluid. In certain embodiments, solid particles may be included in the fluid. The solid particles may be included in only a portion of the calibration fluid, typically at the later stages of the calibration fluid injection. In such cases, the fluid may be a gelled fluid or be pumped at such a rate to ensure suspension of the particles. The particles may be those proppants or particles typically used or that are known to those skilled in the art. In low permeable formations, such as shale gas formations, a low viscosity fluid such as water will be used, which may include friction reducing additives, such as polyacrylamide polymers and those used in slickwater treatments.

The calibration injection method may include a steady continuous injection of fluid at a constant flow rate, or with a step increase in flow rate. The calibration injection method may also include injecting the fluid in two or more pulses wherein each pulse has a different pressure or flow rate from the prior pulse. In certain embodiments, a number of impulse injections with increasing intensity of pressure disturbance (by the way of increasing injection rate) until quality microseismic events are recorded. The calibration injection method may also include injections with a number of flow rate increases of short durations or step-rate injections (e.g. 10 bbl/min {1.6 m³/min}, 20 bbl/min {3.2 m³/min}, etc.) until quality microseismic events are recorded. The injection pressure must be higher than the reservoir (pore) pressure, but can be below or above the formation fracturing pressure (minimum in situ stress), depending on the pressure transmission media and the methods described below. When hydraulic fractures are expected during calibration injections, solid particles may also be injected into the fracture to further evaluate the response of the fracture and the corresponding microseismic events due to the bridging of the solid particles inside the fracture.

The calibration fluid injection creates a pressure disturbance that propagates from the injection point into the formation. The injection point is typically from perforations formed in the wellbore. Microseismic events induced by the pressure disturbance in the formation are recorded by seismic sensors. Such monitoring of microseismic events may be carried out using well known methods for monitoring such events. Examples of such monitoring of microseismic events are described in U.S. Pat. Nos. 6,856,575; 6,947,843 and 6,981,550, U.S. Patent App. Pub. Nos. 2005/01900649 and 2009/0125240, as well as in published international applications WO2004/070424; WO2005/006020, and in U.S. Provisional Patent Application Nos. 61/288,497 and 61/288,640, both filed on Dec. 21, 2009 and each of which is incorporated herein by reference for all purposes. Such monitoring is typically carried out by providing one or more offset well(s) wherein one or more seismic sensors or receivers, such as hydrophones or geophones, may be provided.

By measuring the distance and time lapse between the injection of the calibration fluid and the microseismic events, the pressure transmission velocity of the formation can be determined and the diffusivity or conductivity of the formation or fracture networks of the formation. In formations with higher permeability (e.g. >100 mD), diffusivity of the formation may be measured without the formation of fractures during the calibration injection. In lower permeable formations, fractures will typically be formed. Using microseismic data where fractures are formed or exist, information about both the flow velocity along the fracture length and diffusivity of the formation in the width direction perpendicular to the fracture length direction may be determined. The method of embodiments of the invention may have particular application for extremely low permeable formations with non-conductive natural fractures, such as gas-containing shale formations, where water or slick-water fracturing treatments are used. In such formations, the fluid injection is likely to create a fracture network.

The information derived from the diagnostic operation wherein microseismic events are monitored in accordance with embodiments of the invention can be used in simulation and design modeling. Simulation computer software for such modeling is commercially available and commonly used in designing fracturing treatments. An example of a suitable commercially available software product is that marketed as FracCADE® fracturing design and evaluation software, available from Schlumberger Technology Corp., Sugar Land, Tex., although others may be used as well. A well treatment, which may be a fracturing treatment, may then be performed based upon such models wherein the well is modified by the treatment.

Since the pressure transmission mechanisms are different in different types of formations, the analysis and diagnostic methods will be different depending on the formation types. The following sections describe the methods and analysis based on formation types and based on whether hydraulic fractures or hydraulic fracture networks are created by calibration injections, for the determination of hydraulic properties of the formation, natural fractures, and hydraulic fractures.

1. No Hydraulic Fracture Created by Calibration Injection

The hydraulic diffusivity of the formation rock or the conductive natural fractures that exist in the formation can be determined by a calibration injection with bottomhole injection pressure less than the minimum horizontal in-situ stress. When the bottomhole injection pressure is less than the minimum horizontal in-situ stress, no hydraulic fracture is created by the injection. The calibration injection creates a pressure disturbance in the formation. If the injected volume is small and the injection duration is short, the location and time of the source of the pressure disturbance are known. The transmission velocity in the formation of the pressure disturbance can be calculated from the distance and time lapse between the injection and the measured microseismic events. The velocity of the pressure disturbance can then be used to calculate the hydraulic diffusivity of the formation or the conductive natural fractures, depending on the pressure transmission medium of a formation. For formations with adequate permeability and with no natural fractures, the transmission medium is the formation rock itself (matrix). For formations with conductive natural fractures that have permeability much larger than the formation rock matrix, the transmission medium is the natural fractures. The key point of this method is the small injection volume and short injection duration, so that the location of the pressure source is known to be at or close to the injection point, i.e., the perforated interval of the wellbore. Therefore, the distance between the source and an event can be accurately determined.

1.1 Formations without Natural Fractures

When there is no natural fracture in the formation, the pressure transmission is through the porous formation rock (matrix). The pore pressure change in time and space is controlled by a diffusion process in the formation rock (matrix). Derived from an instantaneous line source solution of the diffusivity equation for two-dimensional fluid flow in the porous media, the following Equation (1) gives the distance over which a significant pressure disturbance is propagated.

$\begin{matrix} {r = \sqrt{\frac{4{kt}}{{\varphi\mu}\; c_{t}}}} & (1) \end{matrix}$

where r is the distance called the radius of investigation,

k is the formation permeability,

φ is the formation porosity,

μ is the reservoir fluid viscosity,

c_(t) is the total compressibility of the formation, and

t is time.

For a fluid injection, the location of the injection source and the starting time of the injection are known. The location and time of microseismic events are determined from microseismic monitoring data processing. When a microseismic event is triggered by the pore pressure disturbance, the distance r is the distance between the injection point and the event location. The time t is the elapse time between the start of injection and the event time. Therefore, the formation diffusivity 17 can be calculated from Equation (1), and expressed as

$\begin{matrix} {\eta = {\frac{k}{{\varphi\mu}\; c_{t}} = \frac{r^{2}}{4t}}} & (2) \end{matrix}$

Furthermore, when the formation properties φ and c_(t), and the reservoir fluid viscosity μ are known, the formation permeability can be calculated by

$\begin{matrix} {k = \frac{{\varphi\mu}\; c_{t}r^{2}}{4t}} & (3) \end{matrix}$

The formation diffusivity or permeability is one of the most important formation properties for hydrocarbon production and for well stimulation planning, design and optimization. The method described here provides an additional, simple and low cost method to determine the formation diffusivity or permeability.

1.2 Formations with Permeable and Connected Natural Fractures

Formations may contain natural fractures that have much higher permeability than the formation rock matrix. For fluid injections into such formations, the pressure disturbance propagates mainly through the natural fracture systems. In other words, the disturbance front in the natural fracture system is far ahead of the disturbance front in the formation rock matrix. The pressure propagation in a natural fracture can be considered as linear along the fracture length. The pressure propagation distance can be determined from a one-dimensional instantaneous source solution in Equation (4) below

$\begin{matrix} {l = \sqrt{\frac{2k_{nf}t}{\varphi_{nf}\mu \; c_{tnf}}}} & (4) \end{matrix}$

where l is the distance along a natural fracture,

k_(nf) is the natural fracture permeability,

φ_(nf) is the natural fracture porosity, and

c_(tnf) is the total compressibility of the natural fracture.

When a microseismic event is triggered by the pore pressure disturbance through a natural fracture, the distance l is the distance along a natural fracture between the injection point and the event location. The time t is the elapsed time between the start of injection and the event time. Therefore, the diffusivity η_(inf) of the natural fracture can be calculated from Equation (4), and expressed as

$\begin{matrix} {\eta_{nf} = {\frac{k_{nf}}{\varphi_{nf}\mu \; c_{tnf}} = \frac{l^{2}}{2t}}} & (5) \end{matrix}$

Furthermore, when the natural fracture properties φ_(nf) and c_(tnf), and the reservoir fluid viscosity μ are known, the natural fracture permeability can be calculated by the following Equation (6)

$\begin{matrix} {k_{nf} = \frac{\varphi_{nf}\mu \; c_{tnf}l^{2}}{2t}} & (6) \end{matrix}$

The pressure transmission path through a natural fracture system may not be a straight line between the injection point and the event location. The distance l can be considered as including certain tortuosity and can be larger than the linear distance between the injection point and the event location.

The diffusivity or permeability of natural fracture is an important factor to consider in hydrocarbon field development and well stimulation design and optimization. The method described here provides an additional, simple and low cost method to determine the diffusivity or permeability of existing natural fractures.

2. Hydraulic Fracture or Hydraulic Fracture Network Created by Calibration Injection

When the injection pressure is larger than the minimum in-situ stress, a calibration injection will create a hydraulic fracture or a hydraulic fracture network. The evaluation method will depend on whether a single bi-wing hydraulic fracture or a hydraulic fracture network is created as described in the following sub-sections.

2.1 Bi-Wing Hydraulic Fracture 2.1.1 Determine Flow Velocity Inside Fracture by Injecting Solids

For a single bi-wing hydraulic fracture created by a calibration injection, the microseismic event cloud shows strong anisotropy in two perpendicular directions: one in the fracture length direction and the other in the fracture width direction. FIG. 1 shows an example of such a microseismic event cloud showing such a fracture. The extent and the speed of the microseismic events front in the fracture length direction are related to the hydraulic fracture propagation, and can be used to determine the hydraulic fracture length and propagation speed. Moreover, the fluid flow velocity inside the hydraulic fracture can be determined by injecting solid particles in the later stage of a calibration injection. When the solid particles flow to the narrow part of the fracture tip, the particles bridge in the narrow fracture width and cause the fracture propagation to stop, which is called “screenout.” A screenout is often accompanied by a characteristic signature in the bottomhole injection pressure behavior, which can be used to determine the time of screenout. With microseismic monitoring, the events occurring in the fracture length direction should reveal the termination of fracture propagation. The fracture length at the time of bridging can be determined from the recorded microseismic events. The time lapse between the injection of particles and the bridging can be obtained from both the microseismic data and the pressure data. With the fracture length and the time lapse, the flow velocity inside the fracture can be calculated and can be used to calibrate other hydraulic fracture parameters, e.g., formation mechanical properties, stresses, leakoff properties, etc., using a hydraulic fracture computer simulator or program. In conventional fracturing calibration, the bottomhole pressure record is often used to calibrate hydraulic fracture parameters. Using the method described here, there is an additional parameter of flow velocity that can be used to calibrate, and provide an increased confidence in the fracture parameters required for treatment design. The calibrated fracture parameters are then used to improve or optimize the subsequent main hydraulic fracturing treatment design.

2.1.2 Determine Formation Hydraulic Diffusivity

For a single bi-wing hydraulic fracture created by a calibration injection, the microseismic event cloud may show strong anisotropy in two perpendicular directions: one in the fracture length direction and the other in the fracture width direction. FIG. 1 shows an example of such a microseismic event cloud showing such a fracture. The extent and speed of the microseismic events front in the fracture width direction are related to the pore pressure propagation in the porous media and can be used to derive the hydraulic diffusivity of the formation. In this case, the pore pressure propagation can be considered as linear in the direction perpendicular to the hydraulic fracture plane. The pressure propagation distance d can be determined from a one-dimensional instantaneous source solution in Equation (7) below

$\begin{matrix} {d = \sqrt{\frac{2{kt}}{{\varphi\mu}\; c}}} & (7) \end{matrix}$

where d is the distance from the hydraulic fracture plane,

k is the formation permeability,

φ is the formation porosity, and

c_(t) is the formation total compressibility.

When a microseismic event is triggered by the pore pressure propagation from a hydraulic fracture, the distance d is the distance between the hydraulic fracture plane and the event location. The time t is the elapsed time between the time when the hydraulic fracture is created and the recorded microseismic event time. Therefore, the formation diffusivity 17 can be calculated from Equation (7), and expressed as

$\begin{matrix} {\eta = {\frac{k}{{\varphi\mu}\; c} = \frac{d^{2}}{2t}}} & (8) \end{matrix}$

Furthermore, when the formation properties φ_(nf), c_(tnf) and the reservoir fluid viscosity μ are known, the formation permeability can be calculated by the following Equation (9)

$\begin{matrix} {k = \frac{{\varphi\mu}\; {cd}^{2}}{2t}} & (9) \end{matrix}$

The formation diffusivity or permeability is one of the most important formation properties for hydrocarbon production and for well stimulation planning, design and optimization. The method described here provides an additional, simple and low cost method to determine the formation diffusivity or permeability.

2.2 Hydraulic Fracture Network 2.2.1 Determine Flow Velocity in Fracture Network by Injecting Solids

For a hydraulic fracture network created by a calibration injection, the microseismic events cloud represents the extent of the fracture network. In certain hydraulic fracture networks, there may be a number of branches, as shown in the schematic of FIG. 2. In a hydraulic fracture network, the fracture width will decrease as the number of branches increases, since the flow rate will split and distribute into more branches. A fracture can be bridged if a proppant slurry flows into the narrow part of a fracture near the fracture tip. The bridging can stop fracture propagation (screenout), and limit the extent of the stimulated reservoir volume. Similar to injecting solids in the bi-wing hydraulic fracture case (2.1.1), when solids are injected in the later stage of a calibration injection into a hydraulic fracture network, the bridging of the branches of a hydraulic fracture network will be revealed as the termination of the microseismic events front propagation. Based on the time lapse between the injection of the solids and the time of the termination of events at the propagation front, the average flow velocity from the wellbore to the tip of the branches can be estimated. In this case, the flow velocity can vary significantly because of the multiple branches, and a hydraulic fracture network computer simulator can be used to match the average flow velocity. By matching this average velocity of a calibration injection in a hydraulic fracture simulation model, the simulation model can then be used for the subsequent main treatment design with increased confidence in the model parameters.

2.2.2 Designing Pad Volume of Pump Schedule Based on Fracture Width and Bridging

For a hydraulic fracture network created by a calibration injection, the microseismic events cloud represents the extent of the fracture network. In certain fracture networks, there may be a number of branches, as shown in the schematic of FIG. 2. In a fracture network, the fracture width will decrease as the number of branches increases, since the flow rate will split and distribute into more branches. A fracture can be bridged if the proppant slurry flows into the narrow part of a fracture near the fracture tip. The bridging can stop fracture propagation (screenout), and limit the extent of the stimulated reservoir volume. In a hydraulic fracture treatment, a volume of pad fluid is injected before proppant slurry stages to prevent premature screenout caused by dehydration and bridging. In conventional fracturing, the design of pad fluid volume is based on fluid leakoff to prevent mainly dehydration screenout and the leakoff is often determined by a conventional calibration injection. In extremely low permeability formations, the leakoff is small and is not the controlling factor for screenout, and the bridging is the main mechanism of screenout. The pad volume may be designed based on bridging to prevent premature screenout and to achieve the desired extent of stimulated reservoir volume.

In order to design the pad volume of a fracturing treatment, a calibration injection is conducted before the main hydraulic fracturing treatment. Microseismic events are recorded during the calibration injection, and the extent and the propagation speed of the fracture network is deduced from the extent and the propagation of the microseismic events. Using a hydraulic fracture network computer simulator, the density of network branches and the fracture width of the network can be estimated by matching the extent and the propagation speed of the simulated fracture network with those deduced from the microseismic data. The branch density and fracture width are then used in the design of the pad volume for the main treatment. Since the main treatment is much larger than the calibration injection, the extent of the fracture network and the number of branches will be significantly larger. The pad volume is designed to create adequate width in the fracture network of the desired extent, without premature screenout, based on the density of network branches and the fracture width of the network estimated from the calibration injection.

2.3 Determination of Hydraulic Fracture Complexity

For formations with extremely low permeability, the pore pressure transmission through the matrix is very slow. Also, in such formations, a calibration injection is most likely to have bottomhole injection pressure larger than the minimum in-situ stress and hence create hydraulic fractures. When the propagation speed of the hydraulic fracture is larger than that of pore pressure front, the front of microseismic events will be related to the hydraulic fracture front instead of the pore pressure front. If the hydraulic fracture is assumed to be a single bi-wing fracture with a constant height and no leakoff, the fracture length can be estimated from a simple Perkins-Kern-Nordgren (PKN) fracture model or other suitable models. The fracture wing length of a bi-wing fracture may be calculated by

$\begin{matrix} {L = {0.68\left( \frac{E^{\prime}q^{3}}{2\mu \; H^{4}} \right)^{0.2}t^{0.8}}} & (10) \end{matrix}$

where L is the fracture length,

t is the time from the start of the injection,

E′ is the plane strain Young's modulus,

q is flow rate into one wing of the fracture, and

H is fracture height.

For a single bi-wing fracture, the flow rate q is one half of the total injection rate Q. If a microseismic event is located near the fracture tip, the distance between the event and the injection point matches the fracture wing length L for the elapse time t between the start of the injection and the event time, the created fracture is a bi-wing fracture.

If the hydraulic fracture has more than two wings, a complex hydraulic fracture network is created. For the early injection time, a few branches may initiate from the wellbore injection point, as shown in the schematic of FIG. 3. In this case, the average flow rate into one of the branches may be approximated as follows:

$\begin{matrix} {q = \frac{Q}{m}} & (11) \end{matrix}$

where Q is the total injection rate and m is the number of branches. The number of branches m can be an indicator of fracture complexity.

For hydraulic fracture networks more complex than a few branches, fractal properties can be used to describe them. Fractal properties have been used to describe natural fractures. A complex hydraulic fracture network initiating from a wellbore may have dendritic features, as shown in FIG. 4, and can be characterized as having a fractal dimension.

The fluid flow from a fully penetrated wellbore into a reservoir formation of constant height is considered to be two dimensional radial flow. The fluid flow in a bi-wing hydraulic fracture is one dimensional linear flow from the wellbore. The fluid flow into a dendritic hydraulic fracture network initiating from the wellbore can be considered as having a flow dimension between a linear one dimensional flow and a radial two dimensional flow. The formulation for flow with a non-integer dimension has been derived. The flow rate q in fractal branches can be calculated from:

$\begin{matrix} {q = \frac{Q/H}{\alpha_{n}s^{n - 1}}} & (12) \\ {where} & \; \\ {{\alpha_{n} = \frac{2\pi^{\frac{\pi}{2}}}{\Gamma \left( \frac{n}{2} \right)}},} & (13) \end{matrix}$

n is the fractal dimension,

Γ is the Gamma function, (defined as Γ(n)=∫₀ ^(∞)t^(n-1)e^(−t)dt, n>0), and

s is the distance from the injection point.

Using the fractal flow rate distribution q in Equation (12), the pressure distribution can be expressed by the following:

$\begin{matrix} {{p(s)} = \left\lbrack {\frac{6{\mu\varphi}\; {E^{\prime}}^{3}Q}{{\alpha_{n}\left( {2 - n} \right)}H^{4}}\left( {L^{2 - n} - s^{2 - n}} \right)} \right\rbrack^{0.25}} & (14) \end{matrix}$

for 1≦n<2, based on the mass conservation and the PKN fracture assumptions. When there is no leakoff, the total fracture volume V is equal to the injection volume.

$\begin{matrix} {V = {{Qt} = {\int_{0}^{L}{\frac{2H}{E^{\prime}}{p(s)}s^{n - 1}{s}}}}} & (15) \end{matrix}$

Substituting, Equation (14) in Equation (15), results in the following:

$\begin{matrix} {{Qt} = {\int_{0}^{L}{{\frac{2H}{E^{\prime}}\left\lbrack {\frac{6{\mu\varphi}\; {E^{\prime}}^{3}Q}{{\alpha_{n}\left( {2 - n} \right)}H^{4}}\left( {L^{2 - n} - s^{2 - n}} \right)} \right\rbrack}^{0.25}s^{n - 1}{s}}}} & (16) \end{matrix}$

Equation (16) can be solved numerically to obtain the value of the fractal dimension n. The value of the fractural dimension n can be used as an indicator of fracture complexity. If n=1, the hydraulic fracture is bi-wing and there is no complexity. If n>1, the hydraulic fracture network can have multiple branches and is complex. The larger the value of n, the more complex is the hydraulic fracture network.

A hydraulic fracture network computer simulator based on fractal dimensions can be developed and used for the design and evaluation of hydraulic fracture treatments that create complex fracture networks. Equations (12)-(16) can be considered as the basis for such hydraulic fracture network computer simulators. By conducting a calibration injection before a main hydraulic fracturing treatment, the fractal dimension can be determined using the above analysis for the created fracture network. The fractal dimension can then be used in the hydraulic fracture network computer simulator to design the main fracturing treatment in the same well or formation with similar fracture complexities.

Thus, it can be seen by the combining microseismic monitoring with calibration injections, a much more detailed analysis can be made of the formation being treated, thus facilitating better a fracturing operation or treatment design.

While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes and modifications without departing from the scope of the invention. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention. 

1. A method of treating a subterranean formation penetrated by a wellbore, the method comprising: performing a diagnostic operation wherein a fluid is introduced into the wellbore at a pressure sufficient to create at least one microseismic event within the formation; monitoring the at least one microseismic event; determining at least one property of the formation surrounding the well based on the monitored at least one microseismic event; and performing a well treatment based upon the determined at least one property of the formation.
 2. The method of claim 1, wherein: the fluid is introduced at a pressure below the fracture pressure of the formation.
 3. The method of claim 1, wherein: the fluid is introduced at a pressure above the fracture pressure of the formation.
 4. The method of claim 1, wherein: the fluid is introduced in two or more pulses wherein each pulse has at least one of a different pressure and a different flow rate from the prior pulse.
 5. The method of claim 1, wherein: the fluid is introduced for a duration of from about 1 minute to about 30 minutes.
 6. The method of claim 1, wherein: a least a portion of the fluid includes a solid particulate material.
 7. The method of claim 1, wherein: the determined property is at least one of diffusivity, permeability, flow velocity, and fracture complexity.
 8. The method of claim 1, wherein: the amount of fluid introduced during the diagnostic operation is from about 50 bbl (7.95 m³) to about 200 bbl (31.8 m³).
 9. The method of claim 1, wherein: the fluid is a non-gelled fluid.
 10. The method of claim 1, wherein: the at least one microseismic event is monitored from an offset well.
 11. The method of claim 1, wherein: the treatment is a fracturing treatment.
 12. The method of claim 1, wherein: the formation is a shale formation.
 13. The method of claim 1, wherein: the at least one property comprises diffusivity, permeability, flow velocity, and/or fracture complexity of a created fracture.
 14. The method of claim 1, wherein: monitoring of the at least one microseismic event occurs while the fluid is being introduced.
 15. The method of claim 1, wherein: monitoring of the at least one microseismic event occurs after the fluid has been introduced.
 16. The method of claim 1, wherein: monitoring of the at least one microseismic event occurs within approximately the first thirty minutes after the fluid is introduced.
 17. The method of claim 1, wherein: at least a portion of the fluid contains solid particles.
 18. A method of treating a subterranean formation penetrated by a wellbore, the method comprising: performing a diagnostic operation wherein a fluid is introduced into the wellbore at a pressure below the fracture pressure of the formation and that is sufficient to create at least one microseismic event within the formation; monitoring the at least one microseismic event; determining at least one property of diffusivity and permeability based on the monitored at least one microseismic event; and performing a well treatment based upon the determined at least one property.
 19. A method of treating a subterranean formation penetrated by a wellbore, the method comprising: performing a diagnostic operation wherein a fluid is introduced into the wellbore at a pressure above the fracture pressure of the formation and sufficient to create at least one microseismic event within the formation; monitoring the at least one microseismic event; determining at least one property of flow velocity and fracture complexity of a created fracture based on the monitored at least one microseismic event; and performing a well treatment based upon the determined at least one property. 